EXHIBIT 99.1

Antero Resources Reports Second Quarter 2013 Financial Results, Utica First Production and Well Rates

Highlights:

· Net daily production averaged 458 MMcfe/d, up 115% over second quarter 2012 production from continuing operations

· Net daily liquids production averaged 4,160 Bbl/d, up 74% over first quarter 2013 liquids production

· Reported GAAP earnings were $131 million and adjusted net income was $34 million

· EBITDAX was $133 million, up 120% over second quarter 2012 EBITDAX from continuing operations

· Current estimated combined net production is 580 MMcfe/d including 8,400 Bbl/d of NGLs and condensate

· Producing 35 MMcfe/d net (6,200 Boe/d) from Utica including 1,500 Bbl/d of liquids with first two wells flowing to processing

· Antero’s first 11 Utica Shale wells had average 24-hour peak rate of 5,600 Boe/d, a 6,300 ft lateral and 57% liquids (ethane recovery assumed)

· Antero’s first four Marcellus wells with shorter stage lengths had average 24-hour peak rate of 25.3 MMcfe/d, a 7,000 ft lateral, 190 ft stages and 45% liquids (ethane recovery assumed)

· 18 Antero-operated drilling rigs currently running in Marcellus and Utica

· Lender commitments on credit facility increased by 21% to $1.45 billion

· Proved reserves increased 47% from year-end 2012 to 6.3 Tcfe at mid-year in each case assuming ethane rejection

Denver, Colorado, August 13, 2013—Antero Resources today released its second quarter 2013 results. The relevant financial statements are included in Antero Resources LLC’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, which has been filed with the Securities and Exchange Commission (“SEC”).

Recent Developments

Effective June 27, 2013, the lender commitments under Antero’s credit facility increased to $1.45 billion. This represents a $250 million increase over Antero’s previous lender commitments of $1.2 billion. The $1.45 billion in commitments can be expanded to the full $1.75 billion borrowing base upon lender approval. The next borrowing base redetermination is expected to occur in September 2013. Antero has $25 million of debt maturing prior to the May 2016 maturity date of the credit facility.

Antero’s proved reserves at June 30, 2013 were 6.3 Tcfe, a 47% increase compared to reserves at December 31, 2012, in each case assuming ethane rejection. The June 30, 2013 reserves exclude 178 MMBbls of ethane which are not recovered through processing due to current SEC price assumptions for ethane and methane. Proved, probable and possible reserves (3P) taken in the aggregate totaled 27.7 Tcfe at June 30, 2013, a 28% increase compared to 3P reserves in the aggregate at December 31, 2012, also assuming ethane rejection. The aggregate 3P reserves exclude 984 MMBbls of ethane. The June 30, 2013 3P reserves were comprised of 18.7 Tcfe in the Marcellus Shale, 5.3 Tcfe in the Utica Shale and 3.8 Tcfe in the Upper Devonian Shale.

Financial Results

Net production for the second quarter of 2013 increased to 42 Bcfe, a 115% increase over net production from continuing operations in the second quarter of 2012. Second quarter 2013 net production increased 20% from net production of 34 Bcfe in the first quarter 2013. The sequential net production increase was primarily driven by production from 26 new wells brought on line in the second quarter of 2013 in the Marcellus Shale. Net production of 42 Bcfe for the second quarter of 2013 was comprised of 39 Bcf of natural gas, 354,000 barrels of NGLs and 25,000 barrels of oil. Net daily production averaged 458 MMcfe/d for the second quarter of 2013 and was comprised of 433 MMcf/d of natural gas (95%), 3,891 Bbl/d of NGLs (4%) and 269 Bbl/d of crude oil (1%). Second quarter 2013 net daily liquids production of 4,160 Bbl/d increased 74% from net daily liquids production in the first quarter of 2013.

Revenues for the second quarter of 2013 were $387 million as compared to $39 million for the second quarter of 2012. Revenues for the second quarter of 2012 included a $56 million unrealized loss on commodity derivative instruments while the second quarter of 2013 included a $181 million unrealized gain on commodity derivatives due to a decline in natural gas prices in the second quarter of 2013. Liquids production (NGLs and oil) contributed 10% of oil, NGLs and natural gas sales before commodity hedges in the second quarter of 2013 compared to less than 1% during the second quarter of 2012. Non-GAAP adjusted net revenues increased 117% to $206 million compared to the second quarter of 2012 (including cash-settled derivatives but excluding unrealized derivative gains and losses). For a reconciliation of adjusted net revenue to operating revenues, the most comparable GAAP measure, please read “Non-GAAP Financial Measures.”

Average natural gas prices before hedges increased 89% from the prior-year quarter to $4.37 per Mcf and average natural gas-equivalent prices before hedges increased 98% to $4.60 per Mcfe. Average realized gas prices including hedges were $4.74 per Mcf for the second quarter of 2013, a 3% decrease as compared to the second quarter of 2012. Average gas-equivalent prices including NGLs, oil and hedges, increased by 1% to $4.94 per Mcfe for the second quarter of 2013 as compared to the second quarter of 2012. For the second quarter of 2013, Antero realized natural gas hedging gains of $0.34 per Mcfe.

The Company had net income of $131 million on a GAAP basis for the second quarter of 2013, including $181 million of unrealized gains on commodity derivatives driven by a decrease in futures prices from the previous quarter-end and the realization of $14 million of commodity gains during the quarter. Excluding the unrealized gain on commodity derivatives and the related income tax expense, adjusted net income, a non-GAAP measure, was $34 million for the second quarter of 2013 as compared to $8 million for the prior year quarter. For a description of adjusted net income and a reconciliation of adjusted net income to net income, please read “Non-GAAP Financial Measures”.

For the second quarter of 2013, cash flow from continuing operations before changes in working capital, a non-GAAP financial measure, increased 195% from the prior-year quarter to $92 million. EBITDAX from continuing operations of $133 million for the second quarter of 2013 was 120% higher than the prior-year quarter due to increased production and revenues. For a description of EBITDAX and cash flow from continuing operations before changes in working capital and reconciliations to their nearest comparable GAAP measures, please read “Non-GAAP Financial Measures”.

Per unit cash production costs (lease operating, gathering, compression, processing and transportation, and production tax) for the second quarter of 2013 were $1.44 per Mcfe a 10% increase compared to $1.31 per Mcfe in the prior year quarter. The increase was primarily driven by processing fees incurred in the Marcellus Shale in the second quarter of 2013 following the opening of the MarkWest Energy Partners, L.P. (MarkWest) Sherwood I plant in October 2012. Per unit depreciation, depletion and amortization expense increased 10% from the prior year quarter to $1.27 per Mcfe, primarily driven by higher depreciation on gas gathering assets as the Company continued to build out its gas gathering system in the rich gas areas of the Marcellus and Utica Shales. On a per unit basis, general and administrative expense for the second quarter of 2013 was $0.33 per Mcfe, a 39% decrease from the second quarter of 2012, primarily driven by the increase in gas-equivalent production.

Capital Spending

Antero’s drilling and completion costs for the six months ended June 30, 2013 were $758 million including $84 million for our 200-miles of water-handling infrastructure projects in the Marcellus and Utica Shales. In addition, during the first half of 2013, $271 million was expended on acreage purchases, $152 million on gas gathering systems and $84 million on water-handling infrastructure. In the Marcellus, $621 million funded the drilling of 74 (72 net) wells and the completion of previously drilled wells as well as $63 million on water-handling infrastructure. A further $126 million was expended on acreage purchases and $96 million on gas gathering systems. In the Utica, $53 million funded the drilling of 11 (9 net) wells and the completion of previously drilled wells and $21 million was expended on water-handling infrastructure, $145 million on acreage purchases and $56 million on gas gathering systems.

Antero Operations

All operational figures are as of the date of this release unless otherwise noted.

During the month of July 2013, Antero estimates that net production averaged 461 MMcfe/d including 4,500 Bbl/d of liquids. Antero’s current estimated net daily production is 580 MMcfe/d, including non-operated production, NGLs and oil. Current estimated gross operated production is 660 MMcf/d. Antero has an additional estimated 160 MMcfe/d of net production associated with 14 completed and tested horizontal wells in the Marcellus and Utica Shales that are shut-in waiting on infrastructure and a number of producing wells that are constrained and waiting on additional pipeline and compression facilities. The current estimated net daily production is comprised of 533 MMcf/d of natural gas and 8,400 Bbl/d of NGLs and condensate. During the second quarter of 2013,

Antero completed 33 gross (32 net) operated wells in the Marcellus and Utica Shales and currently has 57 gross (54 net) operated wells in various stages of drilling, completion, or waiting on completion in the Marcellus and Utica Shale projects.

Utica Shale — Antero is currently operating three drilling rigs, including one intermediate rig, in the rich gas/condensate window of the core of the Utica Shale play in southern Ohio. The Company plans to add a fourth drilling rig in the third quarter of 2013 and a fifth rig in the fourth quarter of 2013.

Initial production from all but one of Antero’s eleven completed horizontal Utica wells has been delayed for several months pending the completion of third-party high pressure gathering infrastructure. The final 16-mile segment of the Seneca to Cadiz pipeline was placed into service last week and enables Antero to transport Utica rich gas production to the MarkWest-owned and operated Cadiz processing facility. The completion of this pipeline was delayed by approximately two months, primarily due to wet weather. Antero subsequently brought on line two Utica Shale horizontal wells that now have access to gas processing facilities. The Seneca to Cadiz pipeline provides Antero with interim access to 185 MMcf/d of combined cryogenic and refrigeration natural gas processing capacity at the Cadiz facility. As an anchor producer, Antero initially has up to 82 MMcf/d of preferred interim processing capacity at Cadiz.

Antero continues to lay both low- and high-pressure gas gathering pipeline to transport its Utica production to the recently completed MarkWest high-pressure gathering and gas processing infrastructure. Including Antero’s Sanford 1H horizontal well located in western Noble County, which went on line in December 2012, Antero’s wells are producing an estimated 35 MMcfe/d net, including 1,300 Bbl/d of NGLs and 200 Bbl/d of condensate. The two wells currently being processed are flowing on a restricted choke with an average flowing casing pressure of 3,550 psi. Ethane is currently being rejected at the processing facility and left in the gas stream. Antero has an additional estimated 90 MMcfe/d of net production in the Utica associated with eight completed and tested horizontal wells that are shut-in waiting to be brought on line sequentially as Antero completes the well and infrastructure start-up process over the next few weeks. The full production capacity of the eight wells will likely be somewhat constrained until the fourth quarter of 2013 when Antero-committed processing capacity at Seneca I is expected to be in-service.

Antero’s first 11 wells in the Utica Shale play have all been tested in order to establish 24-hour peak rates. Based on gas composition analysis and assuming full ethane recovery, the respective 24-hour peak rates have been summarized in the following table:

		Antero Utica Shale Wells - 24-Hour Peak Production Rates(2)
Well Name	County	Oil- Equivalent Rate (Boe/d)(1)	Wellhead Gas (MMcf/d)	Condensate (Bbl/d)	Shrunk Gas (MMcf/d)(1)	NGL (Bbl/d)(1)	% Liquids(1)		BTU	Lateral Length (Feet)
Yontz 1H	Monroe	8,879	38.9	52	33.9	3,177	36	%	1161	5,115
Rubel 1H	Monroe	7,917	31.1	214	25.9	3,391	46	%	1231	6,554
Rubel 2H(2)	Monroe	7,816	30.9	232	25.8	3,284	45	%	1217	6,571
Rubel 3H(2)	Monroe	7,097	28.4	142	23.7	3,003	44	%	1220	6,424
Norman 1H	Monroe	6,181	26.1	45	22.3	2,419	40	%	1186	5,498
Wayne 3HA	Noble	5,852	14.7	1,905	11.6	2,018	67	%	1272	6,712
Wayne 4H	Noble	5,698	14.2	1,922	11.2	1,907	67	%	1265	6,493
Wayne 2H	Noble	4,257	10.9	1,331	8.5	1,503	67	%	1281	6,094
Miley 2H	Noble	3,740	8.6	1,450	6.7	1,172	70	%	1278	6,153
Miley 5HA	Noble	3,369	7.7	1,285	6.0	1,090	70	%	1291	6,296
Sanford 1H	Noble	1,148	1.8	653	1.4	256	79	%	1316	7,159
Average — Ethane Recovery		5,632	19.4	839	16.1	2,111	57	%	1247	6,279

Average — Ethane Rejection(3)		4,682	19.4	839	18.2	805	42	%	1247	6,279

(1)	24-hour peak rates assume full ethane recovery however Antero is currently rejecting ethane due to lack of ethane pipeline and current market prices.
(2)	Rubel 2H and 3H peak rates based on 6-hour and 4-hour flow tests, respectively.
(3)	Average of Antero’s first 11 wells assuming ethane rejection.

The above 24-hour peak rates represent seven of the top eight announced 24-hour peak rates in the Utica Shale play to date. Additionally, Antero is testing optimal well density in the Utica with the three Wayne wells that were drilled on one pad and represent Antero’s first increased density pilot in the Utica utilizing 500 foot interlateral distance. All other wells have been drilled on a 1,000 foot interlateral distance development plan. Antero’s Utica 3P reserves are also based on 1,000 foot interlateral distance. These first 11 Utica Shale wells had an average drilling and completion cost of $11.5 million per well. Antero expects well costs to decline as further development occurs and drilling and completion efforts are optimized.

MarkWest is currently constructing the Seneca processing complex in Noble County, Ohio to process Antero’s rich gas production on a long-term basis. Seneca I, a 200 MMcf/d cryogenic gas processing facility, is expected to begin operations in the fourth quarter 2013. MarkWest is also building Seneca II, a second 200 MMcf/d cryogenic processing facility, which is expected to be in service late in the fourth quarter of 2013. Antero has firm processing capacity of 150 MMcf/d in Seneca I with an option to secure the final 50 MMcf/d of capacity at its election. Should this option be exercised in the third quarter of 2013, Antero will receive an additional 50 MMcf/d of interim capacity at the Seneca II facility until early third quarter 2014. Antero also recently committed to 100 MMcf/d of firm processing capacity at a third 200 MMcf/d facility to be constructed at the Seneca complex, Seneca III, which is expected to be placed on line in the second quarter of 2014. Antero also has the option to increase the Seneca III commitment to the full 200 MMcf/d of plant capacity by early third quarter 2014.

Antero has a compression and condensate stabilization agreement with a third-party to construct and operate three compressor stations in Noble and Monroe Counties, Ohio that have a combined capacity of 340 MMcf/d as well as three condensate stabilization facilities with a combined capacity of 16,000 Bbl/d, all of which are fully dedicated to Antero. The condensate stabilization facilities are necessary to prevent vaporization. The first two compressor stations and condensate stabilization facilities are expected to start up in the fourth quarter of 2013 while the third compressor station and condensate stabilization facility is expected to start up in the first quarter 2014.

In addition to its three wells on line, and eight wells in the process of being placed on line, Antero has seven wells either in the process of drilling, completing or waiting on completion. Antero plans to drill a total of 21 horizontal Utica wells in 2013 with an average lateral length of 6,300 feet. Antero currently holds approximately 101,000 net acres of leasehold in the core of the Utica Shale play. Over 90% of Antero’s acreage is believed to be located in the liquids-rich window.

Marcellus Shale—Antero is currently operating 15 drilling rigs in the Marcellus Shale play, including three intermediate rigs that will drill the vertical section of some horizontal wells to the kick-off point at approximately 6,000 feet. All 15 of these rigs are drilling in northern West Virginia. The Company plans to move one of the drilling rigs to the Utica Shale late in the third quarter of 2013. Currently, Antero has 620 MMcf/d of gross operated production in the Marcellus Shale virtually all of which is from 182 horizontal wells, resulting in 545 MMcfe/d of estimated net production. The 545 MMcfe/d of estimated net production is comprised of approximately 505 MMcf/d of tailgate gas, 6,800 Bbl/d of NGLs and 100 Bbl/d of condensate. Antero has 50 horizontal wells either in the process of drilling, completing or waiting on completion and two dedicated frac crews currently working in West Virginia and several spot frac crews available as needed.

The 182 horizontal Marcellus wells that Antero has completed and placed online to date have an average 24-hour peak rate of 15.6 MMcfe/d and an average 30-day rate of 8.6 MMcfe/d assuming ethane recovery, an average lateral length of approximately 7,000 feet, an average Btu of 1115 and an average drilling and completion cost of $8.7 million per well. In the second quarter of 2013, Antero completed 25 horizontal Marcellus Shale wells with an average 24-hour peak rate of 16.6 MMcfe/d and an average 30-day rate of 9.6 MMcfe/d assuming ethane recovery, an average lateral length of approximately 6,800 feet and an average Btu of 1170.

During the second quarter of 2013, Antero began to complete most of its rich gas Marcellus wells with shorter stage lengths. While Antero’s wells utilizing shorter stage lengths have limited production history, Antero is encouraged by the well results as well as those of other operators in the southwestern core of the Marcellus who have implemented shorter stage lengths and reduced cluster spacing. The following table summarizes Antero’s initial well results from wells utilizing shorter stage lengths.

		Antero Marcellus Shale Wells - 24-Hour Peak Production Rates									Frac
Well Name	County	Equivalent Rate (MMcfe/d)(1)	Wellhead Gas (MMcf/d)	Condensate (Bbl/d)	Shrunk Gas (MMcf/d)(1)	NGL (Bbl/d)(1)	% Liquids(1)		BTU	Lateral Length (Feet)	Stage Length (Feet)
Sweeney 2H	Tyler	26.6	17.5	96	14.5	1,924	46	%	1230	6,395	237
Little Tom 1H	Doddridge	25.9	17.4	—	14.4	1,915	44	%	1225	7,832	191
Sweeney 1H	Tyler	24.9	16.3	90	13.5	1,799	46	%	1230	6,476	180
Webley Fork 1H	Doddridge	23.8	16.0	—	13.3	1,764	44	%	1225	7,261	151
Average — Ethane Recovery		25.3	16.8	47	13.9	1,850	45	%	1228	6,991	190

Average — Ethane Rejection(2)		20.1	16.8	47	15.9	659	21	%	1228	6,991	190

(1) 24-hour peak rates assume full ethane recovery however Antero is currently rejecting ethane due to current market prices.

(2) Average of Antero’s first 7 wells with shorter stage length completions assuming ethane rejection.

Antero’s previous frac design resulted in stage lengths averaging 350 feet. Recent completions have utilized 150 to 250 foot stage lengths. Antero estimates that the incremental cost of the resulting additional frac stages per 7,000 foot lateral is in the $1.5 to $2.0 million per well range.

Antero has access to a total of 400 MMcf/d of cryogenic processing capacity at the MarkWest-owned and operated Sherwood processing facility located in Doddridge County, West Virginia. Currently the Sherwood complex is running at approximately 66% of capacity. Ethane is currently being rejected at the processing facility and left in the gas stream. Antero has committed to a third 200 MMcf/d gas processing plant, Sherwood III, which is expected to go on line in the fourth quarter of 2013, and a fourth 200 MMcf/d plant, Sherwood IV, expected to go online in the second quarter of 2014. These commitments provide Antero access to a total of 800 MMcf/d of Marcellus gas processing capacity.

During the past several months, Antero has experienced capacity constraints in the Marcellus Shale due to delays in the completion of third-party gathering and compression infrastructure. Antero has an additional estimated 70 MMcfe/d of net production in the Marcellus associated with six horizontal wells that are shut-in waiting on infrastructure as well as a number of producing wells that are constrained and waiting on additional pipeline infrastructure. After a two month delay, the 55 MMcfd/d third-party-owned and operated West Union compressor station was completed and placed into service in order to connect highly rich western Doddridge County wells to the Sherwood processing facilities. Additionally, Antero has signed agreements with various third-parties to provide compression services in central and eastern Doddridge County that will add a combined total of 185 MMcf/d of incremental capacity during the remainder of 2013. The 20-inch Zinnia low-pressure line being constructed by a third-party in our Tichenal area has experienced a three month delay due to wet weather. The Zinnia line is expected to be completed later this month and will relieve an estimated 40 MMcfe/d of gross constrained Marcellus production. Further, M3 Appalachia Gathering, LLC recently completed and placed into service the extension of its 16-inch to 24-inch M3 Lateral high pressure pipeline from the Energy Transfer Bobcat Lateral in Harrison County West Virginia to the TETCO interstate pipeline in southern Pennsylvania. Antero currently has 100,000 MMBtu/d of firm transportation on the M3 Lateral, increasing to 300,000 MMBtu/d in the second quarter of 2014.

Antero is currently constructing a 20-inch low pressure gathering line connecting third-party compression located in central Doddridge County to the Sherwood processing facilities to allow for incremental rich gas gathering capacity. This low pressure pipeline, expected to go into service in the fourth quarter of 2013, is ultimately expected to be converted to a high pressure gathering line serving central Doddridge County. Additionally, Antero is constructing a 16-inch low pressure gathering line in eastern Ritchie and southern Tyler Counties to further expand its gathering infrastructure in order to connect several completed wells and allow for delivery of highly rich gas to the Sherwood processing facility. This line is expected to go in service late in the third quarter of 2013.

Antero has 325,000 net acres in the southwestern core of the Marcellus Shale play of which 27% was associated with proved reserves at mid-year 2013. Approximately 80% of Antero’s Marcellus leasehold is prospective for processable rich gas.

Commodity Hedges

Antero has hedged 956 Bcfe of future production using fixed price swaps covering the period from July 1, 2013 through December 2019 at an average NYMEX-equivalent price of $4.86 per MMBtu. Approximately 21% of Antero’s financial hedges are NYMEX hedges and 79% are tied to the Appalachian Basin. For the NYMEX hedges, Antero physically delivers its hedged gas through backhaul firm transportation to Henry Hub, the index for NYMEX pricing, which eliminates basis risk on these NYMEX hedges. For presentation purposes, basin prices are converted by Antero to NYMEX-equivalent prices using current basis differentials in the over-the-counter futures market. Antero has 11 different counterparties to its hedge contracts, all but one of which are lenders under Antero’s bank facility.

The following table summarizes Antero’s hedge positions held as of the date of this release:

	Natural gas equivalent	NYMEX- equivalent
Calendar Year	MMBtu/day	index price
2013	454,000	$	4.71
2014	380,000	$	5.22
2015	390,000	$	5.39
2016	522,500	$	4.99
2017	630,000	$	4.39
2018	450,000	$	4.77
2019	17,500	$	4.86

2013 Outlook

Due to the pending registration of Antero’s securities with the SEC, Antero will no longer provide its outlook for the remainder of 2013. In addition, Antero’s previously announced outlook for 2013 should no longer be relied upon.

Non-GAAP Financial Measures

Adjusted net revenue as set forth in this release represents operating revenues adjusted for certain non-cash items, including unrealized derivative gains and losses and gains and losses on asset sales. We believe that adjusted net revenue is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Adjusted net revenue is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for total operating revenues as an indicator of financial performance. The following table reconciles total operating revenues to adjusted net revenues:

	Three months ended June 30,					Six months ended June 30,
	2012		2013			2012			2013

Total operating revenues	$	38,925	$	387,144		$	592,666		$	448,598
Unrealized commodity derivative (gains) losses	55,904		(181,377		)	(114,498		)	(61,265		)
Gain on sale of gathering system	—		—			(291,305		)	—
Adjusted net revenues	$	94,829	$	205,767		$	186,863		$	387,333

Adjusted net income as set forth in this release represents income from operations before deferred income taxes, adjusted for certain non-cash items. We believe that adjusted net income is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Adjusted net income is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for net income (loss) as an indicator of financial performance. The following table reconciles income from operations to adjusted net income:

	Three months ended June 30,						Six months ended June 30,
	2012			2013			2012			2013

Net income (loss) from continuing operations	$	(33,237	)	$	131,193		$	254,318		$	83,196
Unrealized commodity derivative (gains) losses	55,904			(181,337		)	(114,498		)	(61,265		)
Gain on sale of gathering system	—			—			(291,305		)	—
Provision (benefit) for income taxes	(14,442		)	83,725			183,969			53,325
Adjusted net income	$	8,225		$	33,581		$	32,484		$	75,256

Cash flow from continuing operations before changes in working capital as presented in this release represents net cash provided by operating activities before changes in working capital and exploration expense. Cash flow from continuing operations before changes in working capital is widely accepted by the investment community as a financial indicator of an oil and gas company’s ability to generate cash to internally fund exploration and development activities and to service debt. Cash flow from continuing operations before changes in working capital is also useful because it is widely used by professional research analysts in valuing, comparing, rating and providing investment recommendations of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions. Cash flow from continuing operations before changes in working capital is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for cash flows from continuing operations, investing, or financing activities, as an indicator of cash flows, or as a measure of liquidity.

The following table reconciles net cash provided by operating activities to cash flow from continuing operations before changes in working capital as used in this release:

	Three months ended June 30,				Six months ended June 30,
	2012		2013		2012			2013

Net cash provided by operating activities	$	60,493	$	82,190	$	160,984		$	192,397
Net change in working capital	16,654		10,238		(4,040		)	(14,723		)
Cash flow from operations before changes in working capital	77,147		92,428		156,944			177,674
Cash flow from discontinued operations before changes in working capital	45,803		—		100,280			—
Cash flow from continuing operations before changes in working capital	$	31,344	$	92,428	$	56,664		$	177,674

EBITDAX is a non-GAAP financial measure that we define as net income (loss) before interest expense or interest income, realized and unrealized gains or losses on interest rate derivative instruments, taxes, impairments, depletion, depreciation, amortization, exploration expense, unrealized commodity hedge gains or losses, franchise taxes, stock compensation, business acquisition and gain or loss on sale of assets. EBITDAX, as used and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. EBITDAX should not be considered in isolation or as a substitute for operating income, net income or loss, cash flows provided by operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with GAAP. EBITDAX provides no information regarding a company’s capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position. EBITDAX does not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital, income taxes, franchise taxes, exploration expenses, and other commitments and obligations. However, our management team believes EBITDAX is useful to an investor in evaluating our financial performance because this measure:

· is widely used by investors in the oil and gas industry to measure a company’s operating performance without regard to items excluded from the calculation of such term, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired, among other factors;

· helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure; and

· is used by our management team for various purposes, including as a measure of operating performance, in presentations to our board of directors, as a basis for strategic planning and forecasting and by our lenders pursuant to covenants under our credit facility and the indentures governing our senior notes.

There are significant limitations to using EBITDAX as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss, the lack of comparability of results of operations of different companies and the different methods of calculating EBITDAX reported by different companies. The following table represents a reconciliation of our net (loss) from continuing operations to EBITDAX from continuing operations, a reconciliation of our net income (loss) from discontinued operations to EBITDAX from discontinued operations and a reconciliation of our total EBITDAX to net cash provided by operating activities for the three and six months ended June 30, 2012 and 2013:

	Three months ended June 30,						Six months ended June 30,
	2012			2013			2012			2013
Net income (loss) from continuing operations	$	(33,237	)	$	131,193		$	254,318		$	83,196
Unrealized loss (gain) on commodity derivative contracts	55,904			(181,337		)	(114,498		)	(61,265		)
Interest expense	24,223			33,468			48,593			63,396
Provision (benefit) for income taxes	(14,442		)	83,725			183,969			53,325
Depreciation, depletion, amortization and accretion	22,345			52,856			38,477			93,484
Impairment of unproved properties	1,295			4,803			1,581			6,359
Exploration expense	2,952			7,300			4,756			11,662
Gain on sale of gathering assets	—			—			(291,305		)	—
Other	1,196			600			1,996			1,200
EBITDAX from continuing operations	60,236			132,608			127,887			251,357
Loss	(444,850		)				(404,674		)	—
Unrealized losses on commodity derivative contracts	33,197			—			636			—
Loss on sale of assets	427,232			—			427,232			—
Provision (benefit) for income taxes	(1,717		)	—			12,727			—
Depreciation, depletion, amortization and accretion	31,698			—			63,366			—
Impairment of unproved properties	243			—			993			—
Exploration expense	200			—			412			—
EBITDAX from discontinued operations	46,003			—			100,692			—
Total EBITDAX	106,239			132,608			228,579			251,357
Interest expense and other	(24,223		)	(33,468		)	(48,593		)	(63,396		)
Exploration expense	(3,152		)	(7,300		)	(5,168		)	(11,662		)
Changes in current assets and liabilities	(16,654		)	(10,238		)	4,040			14,723
Other	(1,717		)	588			(17,874		)	1,375
Net cash provided by operating activities	$	60,493		$	82,190		$	160,984		$	192,397

The cash prices realized for oil, NGLs and natural gas production, including the amounts realized on cash settled derivatives, are a critical component in the Company’s performance tracked by investors and professional research analysts in valuing, comparing, rating and providing investment recommendations and forecasts of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions. Due to the GAAP disclosures of various hedging and derivative transactions, such information is now reported in various lines of the income statement.

Antero Resources is an independent oil and natural gas company engaged in the acquisition, development and production of unconventional oil and liquids-rich natural gas properties primarily located in the Appalachian Basin in West Virginia, Ohio and Pennsylvania. Our website is located at www.anteroresources.com.

This release includes “forward-looking statements”. Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero’s control. All statements, other than historical facts included in this release, are forward-looking statements. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas, NGLs and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2012.

For more information, contact Chad Green, Finance Director, at (303) 357-7339 or cgreen@anteroresources.com.

ANTERO RESOURCES LLC AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

December 31, 2012 and June 30, 2013

(Unaudited)

(In thousands)

	2012			2013
Assets
Current assets:
Cash and cash equivalents	$	18,989		$	10,867
Accounts receivable — trade, net of allowance for doubtful accounts of $174 and $10 in 2012 and 2013, respectively	21,296			29,231
Notes receivable — short-term portion	4,555			4,444
Accrued revenue	46,669			66,432
Derivative instruments	160,579			205,221
Other	22,518			11,710
Total current assets	274,606			327,905
Property and equipment:
Oil and natural gas properties, at cost (successful efforts method):
Unproved properties	1,243,237			1,366,023
Proved properties	1,689,132			2,629,529
Gathering systems and facilities	168,930			334,096
Other property and equipment	9,517			11,282
	3,110,816			4,340,930
Less accumulated depletion, depreciation, and amortization	(173,343		)	(266,296		)
Property and equipment, net	2,937,473			4,074,634
Derivative instruments	371,436			388,694
Notes receivable — long-term portion	2,667			—
Other assets, net	32,611			33,915
Total assets	$	3,618,793		$	4,825,148
Liabilities and Equity
Current liabilities:
Accounts payable	$	181,478		$	233,751
Accrued liabilities and other	61,161			84,262
Derivative instruments	—			264
Revenue distributions payable	46,037			54,532
Current portion of long-term debt	25,000			25,000
Deferred income tax liability	62,620			79,722
Total current liabilities	376,296			477,531
Long-term liabilities:
Long-term debt	1,444,058			2,418,217
Deferred income tax liability	91,692			127,915
Other long-term liabilities	33,010			44,552
Total liabilities	1,945,056			3,068,215
Equity:
Members’ equity	1,460,947			1,460,947
Accumulated earnings	212,790			295,986
Total equity	1,673,737			1,756,933
Total liabilities and equity	$	3,618,793		$	4,825,148

ANTERO RESOURCES LLC AND SUBSIDIARIES

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)

Three Months Ended June 30, 2012 and 2013

(Unaudited)

(In thousands)

	2012			2013
Revenue:
Natural gas sales	$	44,688		$	172,332
Natural gas liquids sales	—			17,244
Oil sales	277			2,085
Realized and unrealized gain (loss) on derivative instruments (including unrealized gains (losses) of $(55,904) and $181,337 in 2012 and 2013, respectively)	(6,040		)	195,483
Total revenue	38,925			387,144
Operating expenses:
Lease operating expenses	1,866			1,454
Gathering, compression, processing, and transportation	20,079			48,670
Production taxes	3,371			10,108
Exploration expenses	2,952			7,300
Impairment of unproved properties	1,295			4,803
Depletion, depreciation and amortization	22,321			52,589
Accretion of asset retirement obligations	24			267
General and administrative	10,473			13,567
Total operating expenses	62,381			138,758
Operating income (loss)	(23,456		)	248,386
Interest expense	(24,223		)	(33,468		)
Income (loss) from continuing operations before income taxes and discontinued operations	(47,679		)	214,918
Income tax (expense) benefit	14,442			(83,725		)
Income (loss) from continuing operations	(33,237		)	131,193
Discontinued operations:
Loss from results of operations and sale of discontinued operations	(444,850		)	—
Net income (loss) and comprehensive income (loss) attributable to Antero equity owners	$	(478,087	)	$	131,193

ANTERO RESOURCES LLC AND SUBSIDIARIES

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)

Six Months Ended June 30, 2012 and 2013

(Unaudited)

(In thousands)

	2012			2013
Revenue:
Natural gas sales	$	89,822		$	294,278
Natural gas liquids sales	—			27,816
Oil sales	325			2,962
Realized and unrealized gain on derivative instruments (including unrealized gains of $114,498 and $61,265 in 2012 and 2013, respectively)	211,214			123,542
Gain on sale of gathering system	291,305			—
Total revenue	592,666			448,598
Operating expenses:
Lease operating expenses	2,559			2,525
Gathering, compression, processing, and transportation	31,654			89,640
Production taxes	7,113			18,727
Exploration expenses	4,756			11,662
Impairment of unproved properties	1,581			6,359
Depletion, depreciation and amortization	38,431			92,953
Accretion of asset retirement obligations	46			531
General and administrative	19,646			26,284
Total operating expenses	105,786			248,681
Operating income	486,880			199,917
Interest expense	(48,593		)	(63,396		)
Income from continuing operations before income taxes and discontinued operations	438,287			136,521
Income tax expense	(183,969		)	(53,325		)
Income from continuing operations	254,318			83,196
Discontinued operations:
Loss from results of operations and sale of discontinued operations	(404,674		)	—
Net income (loss) and comprehensive income (loss) attributable to Antero equity owners	$	(150,356	)	$	83,196

ANTERO RESOURCES LLC AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows

Six Months Ended June 30, 2012 and 2013

(Unaudited)

(In thousands)

	2012			2013
Cash flows from operating activities:
Net income (loss)	$	(150,356	)	$	83,196
Adjustment to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, amortization, and accretion	38,477			93,484
Impairment of unproved properties	1,581			6,359
Unrealized gains on derivative instruments, net	(114,498		)	(61,265		)
Gain on sale of assets	(291,305		)	—
Loss on sale of discontinued operations	427,232			—
Deferred income tax expense	165,669			53,325
Depletion, depreciation, amortization, accretion, and impairment of unproved properties — discontinued operations	64,359			—
Unrealized losses on derivative instruments, net — discontinued operations	636			—
Deferred income tax expense — discontinued operations	12,727			—
Other	2,422			2,575
Changes in current assets and liabilities:
Accounts receivable	(15,791		)	(7,935		)
Accrued revenue	18,535			(19,763		)
Other current assets	(3,162		)	10,808
Accounts payable	(17,058		)	(1,436		)
Accrued liabilities	10,641			20,137
Revenue distributions payable	575			8,495
Other	10,300			4,417
Net cash provided by operating activities	160,984			192,397
Cash flows from investing activities:
Additions to proved properties	(4,451		)	—
Additions to unproved properties	(263,737		)	(271,003		)
Drilling costs	(377,199		)	(757,877		)
Additions to gathering systems and facilities	(47,982		)	(151,737		)
Additions to other property and equipment	(1,300		)	(1,766		)
Proceeds from asset sales	811,253			—
Changes in other assets	(257		)	3,975
Net cash from (used in) investing activities	116,327			(1,178,408		)
Cash flows from financing activities:
Issuance of senior notes	—			231,750
Borrowings (repayments) on bank credit facility, net	(275,000		)	743,000
Payments of deferred financing costs	—			(5,663		)
Other	(79		)	8,802
Net cash provided by (used in) financing activities	(275,079		)	977,889
Net increase (decrease) in cash and cash equivalents	2,232			(8,122		)
Cash and cash equivalents, beginning of period	3,343			18,989
Cash and cash equivalents, end of period	$	5,575		$	10,867
Supplemental disclosure of cash flow information:
Cash paid during the period for interest	$	(45,064	)	$	(62,246	)
Supplemental disclosure of noncash investing activities:
Increase in accounts payable for additions to properties, gathering systems and facilities	$	31,593		$	54,051

OPERATING DATA

The following table sets forth selected operating data (as recast for discontinued operations) for the three months ended June 30, 2012 compared to the three months ended June 30, 2013:

	Three Months Ended June 30,						Amount of Increase
	2012			2013			(Decrease)			Percent Change
	(in thousands, except per unit and production data)
Operating revenues:
Natural gas sales	$	44,688		$	172,332		$	127,644		286	%
NGL sales	—			17,244			17,244			*
Oil sales	277			2,085			1,808			653	%
Realized gains on derivative instruments	49,864			14,146			(35,718		)	(72	)%
Unrealized gains (losses) on derivative instruments	(55,904		)	181,337			237,241			*
Total operating revenues	38,925			387,144			348,219			895	%
Operating expenses:
Lease operating expense	1,866			1,454			(412		)	(22	)%
Gathering, compression, processing, and transportation	20,079			48,670			28,591			142	%
Production taxes	3,371			10,108			6,737			200	%
Exploration expenses	2,952			7,300			4,348			147	%
Impairment of unproved properties	1,295			4,803			3,508			271	%
Depletion, depreciation, and amortization	22,321			52,589			30,268			136	%
Accretion of asset retirement obligations	24			267			243			1,013	%
General and administrative	10,473			13,567			3,094			30	%
Total operating expenses	62,381			138,758			76,377			122	%
Operating income (loss)	(23,456		)	248,386			271,842			*

Interest expense	(24,223		)	(33,468		)	(9,245		)	38	%
Income (loss) before income taxes	(47,679		)	214,918			262,597			*
Income tax benefit (expense)	14,442			(83,725		)	(98,167		)	*
Income (loss) from continuing operations	(33,237		)	131,193			164,430			*
Loss from discontinued operations	(444,850		)	—			444,850			*
Net income (loss) attributable to Antero members	$	(478,087	)	$	131,193		$	609,280		*

EBITDAX from continuing operations	$	60,236		$	132,608		$	72,372		120	%

Total EBITDAX	$	106,239		$	132,608		$	26,369		25	%

Production data:
Natural gas (Bcf)	19			39			20			104	%
NGLs (MBbl)	—			354			354			*
Oil (MBbl)	4			25			21			585	%
Combined (Bcfe)	19			42			23			115	%
Daily combined production (MMcfe/d)	213			458			245			115	%
Average prices before effects of hedges:
Natural gas (per Mcf)	$	2.31		$	4.37		$	2.06		89	%
NGLs (per Bbl)	$	—		$	48.70		$	*		*
Oil (per Bbl)	$	77.16		$	85.07		$	7.91		10	%
Combined (per Mcfe)	$	2.32		$	4.60		$	2.28		98	%
Average realized prices after effects of hedges:
Natural gas (per Mcf)	$	4.89		$	4.74		$	(0.15	)	(3	)%
NGLs (per Bbl)	$	—		$	48.70		$	48.70		*
Oil (per Bbl)	$	77.16		$	80.70		$	3.54		5	%
Combined (per Mcfe)	$	4.90		$	4.94		$	0.04		1	%
Average costs (per Mcfe):
Lease operating costs	$	0.10		$	0.03		$	(0.07	)	(70	)%
Gathering, compression, processing, and transportation	$	1.04		$	1.17		$	0.13		13	%
Production taxes	$	0.17		$	0.24		$	0.07		41	%
Depletion, depreciation, amortization, and accretion	$	1.15		$	1.27		$	0.12		10	%
General and administrative	$	0.54		$	0.33		$	(0.21	)	(39	)%

OPERATING DATA

The following table sets forth selected operating data (as recast for discontinued operations) for the six months ended June 30, 2012 compared to the six months ended June 30, 2013:

	Six Months Ended June 30,						Amount of Increase
	2012			2013			(Decrease)			Percent Change
	(in thousands, except per unit and production data)
Operating revenues:
Natural gas sales	$	89,822		$	294,278		$	204,456		228	%
NGL sales	—			27,816			27,816			*
Oil sales	325			2,962			2,637			811	%
Realized gains on derivative instruments	96,716			62,277			(34,439		)	(36	)%
Unrealized gains on derivative instruments	114,498			61,265			(53,233		)	(46	)%
Gain on sale of gathering system	291,305			—			(291,305		)	*
Total operating revenues	592,666			448,598			(144,068		)	(24	)%
Operating expenses:
Lease operating expense	2,559			2,525			(34		)	(1	)%
Gathering, compression, processing, and transportation	31,654			89,640			57,986			183	%
Production taxes	7,113			18,727			11,614			163	%
Exploration expenses	4,756			11,662			6,906			145	%
Impairment of unproved properties	1,581			6,359			4,778			302	%
Depletion, depreciation, and amortization	38,431			92,953			54,522			142	%
Accretion of asset retirement obligations	46			531			485			1,054	%
General and administrative	19,646			26,284			6,638			34	%
Total operating expenses	105,786			248,681			142,895			135	%
Operating income (loss)	486,880			199,917			(286,963		)	(59	)%

Interest expense	(48,593		)	(63,396		)	(14,803		)	30	%
Income before income taxes	438,287			136,521			(301,766		)	(69	)%
Income tax expense	(183,969		)	(53,325		)	130,644			(71	)%
Income from continuing operations	254,318			83,196			(171,122		)	(67	)%
Loss from discontinued operations	(404,674		)	—			404,674			*
Net income (loss) attributable to Antero members	$	(150,356	)	$	83,196		$	233,552		*

EBITDAX from continuing operations	$	127,887		$	251,357		$	123,470		97	%

Total EBITDAX	$	228,579		$	251,357		$	22,778		10	%

Production data:
Natural gas (Bcf)	35			73			38			105	%
NGLs (MBbl)	—			559			559			*
Oil (MBbl)	4			35			31			764	%
Combined (Bcfe)	35			76			41			116	%
Daily combined production (MMcfe/d)	195			421			226			116	%
Average prices before effects of hedges:
Natural gas (per Mcf)	$	2.53		$	4.05		$	1.52		60	%
NGLs (per Bbl)	$	—		$	49.75		$	49.75		*
Oil (per Bbl)	$	80.05		$	85.36		$	5.31		7	%
Combined (per Mcfe)	$	2.54		$	4.27		$	1.73		68	%
Average realized prices after effects of hedges:
Natural gas (per Mcf)	$	5.26		$	4.91		$	(0.35	)	(7	)%
NGLs (per Bbl)	$	—		$	49.75		$	49.75		*
Oil (per Bbl)	$	80.05		$	79.14		$	(0.91	)	(1	)%
Combined (per Mcfe)	$	5.26		$	5.09		$	(0.17	)	(3	)%
Average costs (per Mcfe):
Lease operating costs	$	0.07		$	0.03		$	(0.04	)	(57	)%
Gathering, compression, and transportation	$	0.89		$	1.18		$	0.29		33	%
Production taxes	$	0.20		$	0.25		$	0.05		25	%
Depletion, depreciation, amortization, and accretion	$	1.08		$	1.23		$	0.15		14	%
General and administrative	$	0.55		$	0.35		$	(0.20	)	(36	)%

Antero Resources LLC 8-K